1. Field of the Invention
The present invention relates to process for recovering a processing liquid and, more particularly, to a process for recovering a processing liquid from a mixture comprising the processing liquid, at least one component that is more volatile than the processing liquid, and at least one component that is less volatile than, and can be dissolved or suspended in, the processing liquid.
2. Description of the Prior Art
There are numerous industrial processes wherein a liquid, hereinafter referred to as a processing liquid, which can comprise one or more components, is used in such a fashion that it becomes contaminated with, or contains, various components, some of which are more volatile than the processing liquid and some of which are less volatile and can be dissolved in the processing liquid. Usually, the components in the processing liquid are contaminants, although they may be desirable, recovered components, depending on the process in which the processing liquid is used. In such cases, it is almost universally desirable to separate the processing liquid from the less volatile and more volatile components so that the processing liquid can be reused in the process or simply recovered in a substantially pure state for reuse or other uses.
Numerous examples of the above described general scheme of using a processing liquid abound. For example, it is well known that natural gas produced from oil and gas wells, in addition to containing gaseous hydrocarbons, such as methane, ethane, etc., almost invariably contains water and acidic gases, such as CO.sub.2 and H.sub.2 S. In cases where the natural gas contains water, it is very common for so called gas hydrates or clathrate hydrates to form. These clathrate hydrates are crystalline compounds that occur when water forms a cage-like structure around guest molecules, particularly gaseous molecules.
While the phenomena can occur in any system wherein there is water and gaseous compounds, e.g., hydrocarbons, the problem, at times, becomes especially acute in the petroleum industry, not only with respect to the production of gaseous hydrocarbons such as natural gas, but also in the transporting and processing of natural gas. As noted, typical gas hydrates formed in petroleum (hydrocarbon) environments are composed of water and one or more guest molecules, such as methane, ethane, propane, isobutane, nitrogen, carbon dioxide, and hydrogen sulfide. However, it is also known that other guest molecules such as nitrous oxide, acetylene, vinyl chloride, ethyl bromide, oxygen, etc., can form clathrate hydrates.
With particular reference to natural gas systems and by example only, when gas hydrate crystals form, they can become a nuisance at least and pose a serious problem at worst. Gas hydrates can block transmission lines and plug blowout preventers, jeopardize the foundations of deepwater platforms and pipelines, collapse tubing and casing, and foul process equipment, such as heat exchangers, compressors, separators, and expanders. To overcome these problems, several thermodynamic measures are possible in principal: removal of free water, maintaining an elevated temperature and/or reduced pressure, or the addition of freezing point depressants. As a practical matter, the last mentioned measure, i.e., adding freezing point depressants, has been most frequently applied. Thus, lower alcohols, such as methanol, ethanol, etc., and glycols have been added to act as antifreezes.
While processing liquids such as alcohols and glycols used in natural gas production, transportation, and processing are effective at reducing gas hydrate formation, their use is not without problems. As is well known, the production of natural gas is frequently accompanied by the production of brine, containing sodium chloride and other water-soluble salts. While these halides, such as the alkali metal halides, are readily soluble in water, they also exhibit substantial solubility in the alcohols and glycols used to prevent gas hydrate formation. Accordingly, the processing liquid--in this case the alcohol, glycol, or the like--becomes contaminated with dissolved salts present in the produced water, as well as with certain gases, which, depending on the particular gas, are soluble in the processing liquid. Thus, this presents a specific example where a processing liquid has been used, in this case to prevent hydrate formation, and has now become contaminated with a more volatile component and a less volatile, and in this case dissolved, component.
Again, using the example of natural gas production, transportation, and processing, it is necessary that the natural gas be freed of acidic components, such as CO.sub.2, H.sub.2 S, sulfur oxides, etc., some of which are quite toxic, all of which can lead to severe corrosion problems and in certain cases the formation of unwanted by-products. It is common to scrub the natural gas stream with processing liquids such as liquid amines, particularly alkanolamines such as monoethanolamine (MEA); diethanolamine (DEA); methyldiethanolamine (MDEA), as well as glycols such as mono-, di-, or tri-ethylene glycol. Since scrubbing of natural gas to remove acidic gases is normally conducted on natural gas streams that have been substantially freed of water, the dissolved salt content of the natural gas stream from the gas stream is generally quite small. However, even though the ingress of dissolved salt is low from the natural gas stream, continuous use of the amine process liquid for acid gas removal tends to cause the amine to break down with contaminants and create heat-stable, unregenerable salts. If the residual buildup of heat-stable salts (HSS) is permitted to build to typical levels in excess of 1% by weight, the amine performance will decline, corrosion increases rapidly with a decline in pH, and the amine solution begins to foam, creating excessive process liquid losses. Accordingly, the processing liquid, e.g., the alkanolamine, will generally contain dissolved, less volatile components at a much smaller concentration than in the case of an alcohol or glycol used to prevent gas hydrate formation. Nonetheless, even in this instance, the processing liquid now presents a case where, after use, it contains more volatile components, e.g., CO.sub.2 H.sub.2 S, etc., and perhaps a small amount of less volatile and dissolved component.
In the case where treatment of the natural gas to prevent gas hydrate formation and/or remove acidic gases is conducted on offshore platforms, several problems are encountered. For one, the alcohols, glycols, and alkanolamines can be toxic to marine life and accordingly, once spent, e.g., saturated with contaminants that they are being used to remove, cannot be discharged overboard. Aside from ecological concerns, such a method is economically not feasible since it requires a constant replenishment of the processing liquid. Indeed, such a process would not be economically feasible in land-based refineries, chemical plants, or the like.
U.S. Pat. Nos. 5,152,887; 5,158,649; 5,389,208; and 5,441,605 all deal with processes and apparatus for reclaiming and/or concentrating waste aqueous solutions of gas treating chemicals. Additionally, U.S. Pat. Nos. 4,315,815; and 4,770,747 likewise deal with processes for reclaiming or recovering gas-treating liquids. U.S. Pat. No. 5,389,208, incorporated herein by reference for all purposes, discloses and claims a method for reclaiming an impurity-containing waste aqueous solution of a gas-treating chemical that basically involves vacuum distillation of the spent material under temperature conditions that prevent decomposition of the gas-treating chemical and in such a fashion that the process can be operated in apparatuses made of carbon steel, as opposed to more exotic materials of construction, without causing substantial corrosion of the apparatus.